Raw natural gas comes from three types of wells: (1) oil wells—natural gas that comes from oil wells is typically termed ‘associated gas’. This gas can exist separate from oil in the formation (free gas), or dissolved in the crude oil (dissolved gas); vast amounts of gases are produced as a by-product of the crude stabilization process, and often disposed of using flaring or re-injected; and (2) gas wells and (3) condensate wells—natural gas from gas and condensate wells, in which there is little or no crude oil, is termed ‘non-associated gas’. Gas wells typically produce raw natural gas by itself, while condensate wells produce free natural gas along with a semi-liquid hydrocarbon condensate.
Whatever the source of the natural gas, once separated from crude oil (if present) it commonly exists in mixtures with other hydrocarbons; principally ethane, propane, butane, and pentanes. In addition, raw natural gas contains water vapor, hydrogen sulfide (H2S), carbon dioxide, helium, nitrogen, and other compounds. While the ethane, propane, butane, and pentanes must be removed from natural gas, this does not mean that they must be wasted. In fact, associated hydrocarbons, known as ‘natural gas liquids’ (NGLs) can be very valuable by-products of natural gas processing. NGLs include ethane, propane, butane, iso-butane, and natural gasoline. Today it is commonly processed and fractionated into (i) methane (residue gas), or (ii) methane (residue gas), ethane, propane and butane (LPG) and condensate (C5+).
Natural gas processing consists of separating all of the various hydrocarbons and fluids from the pure natural gas, to produce what is known as ‘pipeline quality’ dry natural gas. The resulting NGLs are sold separately and have a variety of different uses; including enhancing oil recovery in oil wells, providing raw materials for oil refineries or petrochemical plants, and as sources of energy.
In a general trend to save and conserve the valuable energy resources of current oil fields, and eliminate flaring, the associated gases are being collected and processed as natural gas liquids (NGL) for sale in more and more oil fields around the world, both onshore and offshore fields. Major transportation pipelines usually impose restrictions on the make-up of the natural gas that is allowed into the pipeline. That means that before the natural gas can be transported it must be purified.
The actual practice of processing natural gas to pipeline dry gas quality levels can be quite complex, but usually involves four main processes to remove the various impurities: Oil and Condensate Removal, Water Removal, Separation of Natural Gas Liquids, and Sulfur and Carbon Dioxide Removal. Present methods of removal of hydrogen sulfide, for example, include employing an iron sponge or Sulfatreat™.
In addition to the four processes above, heaters and scrubbers are installed, usually at or near the wellhead. The scrubbers serve primarily to remove sand and other large-particle impurities. The heaters ensure that the temperature of the gas does not drop too low. With natural gas that contains even low quantities of water, natural gas hydrates have a tendency to form when temperatures drop. These hydrates are solid or semi-solid compounds, resembling ice like crystals. Should these hydrates accumulate, they can impede the passage of natural gas through valves and gathering systems. To reduce the occurrence of hydrates, small natural gas-fired heating units are typically installed along the gathering pipe wherever it is likely that hydrates may form.
As well as the impurities discussed above, landfills and sewage treatment plants contain carbon dioxide, hydrogen sulfide, volatile organic sulfides and siloxanes. Waste from industrial and domestic source is often discharged into landfill sites and sewage treatment plants, along with a variety of biological organic matter. The organic matter in the waste decomposes to produce bio-gas containing various volatile organic compounds, such as methane, carbon dioxide, hydrogen sulfide and volatile organic compounds, such as siloxanes, organic halides and organic sulfides. The bio-gas can be used to fuel various combustion engines to produce power, or both heat and power. However, the bio-gas from landfill sites and sewage treatment plants is contaminated with siloxanes. When an engine burns siloxane-contaminated bio-gas, the siloxanes, on oxidation, forms precipitates of silicon dioxide. The precipitates are deposited on engine parts such as turbine blades, pistons, cylinders, heat exchangers and emission control equipment. The deposits increase the abrasion of engine surfaces, leading to a loss of engine efficiency and premature engine failure. The deposits also poison catalytic converters in emission control equipment. Similarly, the combustion products of organic sulfides and hydrogen sulfides are corrosive in nature, requiring increased maintenance and replacement of corroded parts like cylinder heads, pistons, turbine blades and wheels. It is desirable to remove these contaminants prior to the bio-gas entering the combustion chamber of the power generation system.
According to the EPA's most recent data (2007), the U.S. has over 1,700 active landfills. Though the number of landfills has significantly decreased over the last 20 years, the average size of landfills has increased. Landfill sites produce methane and carbon dioxide gases due to the natural decomposition of solid waste material. Solid waste landfills are the second largest source of human-related methane emissions in the United States, accounting for approximately 23 percent of these emissions in 2007. In fact, these methane emissions from landfills represent a lost opportunity to capture and use a significant energy resource. Instead of allowing landfill gas (LFG) to escape into the air, it can be captured, converted, and used as an energy source. Financial benefits and improved community relations now provide the landfill industry with multiple incentives to employ bio-gas conditioning systems in the management of these gases.
Similarly, approximately 14,000 wastewater treatment facilities (WWTFs) operate in the United States, ranging in capacity from several hundred million gallons per day (MGD) to less than 1 MGD. Roughly 1,000 of these facilities operate with a total influent flow rate greater than 5 MGD, but only 544 of these facilities employ anaerobic digestion to process the wastewater. Moreover, only 106 WWTFs utilize the bio-gas produced by their anaerobic digesters to generate electricity and/or thermal energy. If the remaining WWTFs were to install combined heat and power technologies, approximately 340 MW of clean electricity could be generated, offsetting 2.3 million metric tons of carbon dioxide emissions annually. These reductions are equivalent to planting approximately 640,000 acres of forest, or the emissions of approximately 430,000 cars.
Utilization of bio-gas conditioning systems provides landfills and WWTFs with an opportunity to collect and dispose of the high levels of methane found in landfill and WWTF digester gases. Currently, many landfills and WWTFs are using untreated gas containing impurities such as sulfur, chlorine, silicon and moisture, to generate power and fire boilers. This untreated gas can make existing equipment such as boilers, engines, fuel cells and turbines susceptible to increased damages, increased maintenance costs and shorter life spans.
Purification of gas mixtures comprising a hydrocarbon or nitrogen, and carbon dioxide can be done by absorbing the carbon dioxide in a suitable liquid, typically amines or glycols. The absorbing liquids, once saturated with carbon dioxide, are regenerated in a separate step by exposing them to higher temperatures and lower pressures, causing the absorbed carbon dioxide to volatilize and separate out. This technique is used for purification of bio-gas methane from its contaminating carbon dioxide, as well as in coal burning plant effluents for carbon dioxide sequestration. The capital and running costs of such purification plants tend to increase rapidly with increasing concentration and volumes of carbon dioxide. However, liquids employed as absorbents tend to be corrosive, and thus relatively high maintenance costs are typically associated with such plants. Accordingly, other methods of separating hydrocarbons from carbon dioxide have been used. Among such other methods are those involving liquefaction of the gas mixture and fractional distillation of the liquid to produce a product vapor fraction relatively lean in carbon dioxide.
Fractional distillation has also been employed to separate a mixture of various hydrocarbons in a natural gas stream. Thus, the natural gas stream may contain methane with various proportions of ethane, propane, butane, pentane and hexane (commonly called C2-C6 hydrocarbons), as well as other higher hydrocarbons, commonly termed Natural Gas Liquids (NGLs). Cryogenics, employed in conjunction with fractional distillation, enables condensation of the C2-C6 components, with or without pressure, and then step-wise distillation of the desired component, based on its boiling point at the said operational pressure. This process is commonly employed in the oil and gas industry, especially for removal of the higher value NGLs from the lower value natural gas (mainly methane, CH4), the latter being sent to the pipeline as the commonly available natural gas, with a calorific value of 950-1000 Btu/scf.
Pressure swing adsorption (PSA) is a known method of separating the components of a gaseous mixture by passage through a bed of adsorbent that preferentially adsorbs at least one component under pressure. A gaseous product that is relatively lean in the adsorbed component(s) passes out of the bed. The bed is regenerated by subjecting it to a lower pressure thereby desorbing the previously adsorbed component(s). The adsorbent is generally a molecular sieve, e.g. a zeolite or carbon molecular sieve. In more efficient commercial PSA processes, a plurality of beds is employed and the incoming gas stream for separation is switched between the beds so as to facilitate the continuous supply of gaseous products.
The equilibrium quantity of a gas adsorbed on a molecular sieve is not solely a function of pressure but also one of temperature. Indeed, some commercial gas separation processes effect separation by temperature swing rather than pressure swing. Although typical zeolite molecular sieves have gaseous adsorption equilibrium values that are achieved rapidly and then remain constant with time, carbon molecular sieves exhibit dynamic sieving behavior before coming to equilibrium (the former effects the separation); both kinds of sieves increase in temperature as gas is adsorbed since heat of adsorption is liberated, and decrease in temperature again when gas is desorbed. These changes in temperature are substantially equal. There is, however, an additional increase in temperature as a result of the compression of the incoming gas mixture for separation. A substantial proportion of the heat of compression is removed in an after cooler that is conventionally associated with the compressor. There is also a reduction in temperature associated with the reduction in pressure during the desorption step. It might be expected that the PSA process would therefore run at an average temperature below ambient in view of there being net refrigeration that is produced by the pressure reduction required to effect the desorption step. In practice, however, only a relatively small proportion of the refrigeration developed during the desorption step is employed to reduce the temperature of the bed of adsorbent, and most of the refrigeration generated during desorption is wasted in the gas that is vented to the atmosphere. Thus, in practice, the average temperature at which the pressure swing adsorption process operates is usually above rather than below ambient temperature. Because the equilibrium amount of gas that is adsorbed increases with decreasing temperature, the failure to efficiently use the refrigeration generated leads to unnecessarily high specific power consumption. Moreover, the temperature rise that takes place during adsorption is also undesirable since lower temperatures generally favor adsorption. The temperature fall that takes place during desorption is similarly undesirable since in general higher temperatures favor desorption.
H2S, hydrogen sulfide, a common contaminant of bio-gas from landfills and anaerobic digester plants, as well as in some natural gas streams, is commonly removed from the gas stream by absorption into granular iron or sponge iron powder, or similar alloyed media. The hydrogen sulfide chemically reacts with the iron in the media to form iron sulfide, and leaves a gas stream substantially purified of the sulfide contaminant and thus less corrosive to combustion processes like power-plants for energy generation. The granular iron sulfide, however, cannot be regenerated without a substantial energy penalty, and is commonly disposed of in a landfill. Other methods for H2S removal include hydrodesulfurization (HDS), which involves use of hydrogen gas with catalysts for removal of the sulfide species.
All the above processes are either energy intensive, or consume raw materials which cannot be easily regenerated. Cryogenics and fractional distillation are prohibitively energy intensive for small-scale plants, while pressure and temperature swing adsorption (PSA and TSA) are prohibitively expensive for large-scale plants, and energy intensive for small-scale plants. HDS is commonly used in petroleum refineries, and is especially suitable only for large-scale plants. The present invention reflects efforts to solve at least some if not all of the above problems.